In oil and gas exploration it is desirable to understand the structure and properties of the geological formation surrounding a borehole, in order to determine if the formation contains hydrocarbon resources (oil and/or gas), to estimate the amount and producibility of hydrocarbon contained in the formation, and to evaluate the best options for completing the well in production. A significant aid in this evaluation is the use of wireline logging and/or logging-while-drilling (LWD) measurements of the formation surrounding the borehole (referred to collectively as “logs” or “log measurements”). Typically, one or more logging tools are lowered into the borehole and the tool readings or measurement logs are recorded as the tools traverse the borehole. These measurement logs are used to infer the desired formation properties.
Petrophysical parameters of a geologic formation which are typically used to determine whether the formation will produce viable amounts of hydrocarbons include the formation porosity PHI, fluid saturation S, the volume of the formation, and its permeability K. Formation porosity is the pore volume per unit volume of formation; it is the fraction of the total volume of a sample that is occupied by pores or voids. The saturation S of a formation is the fraction of a its pore volume occupied by the fluid of interest. Thus, water saturation SW is the fraction of the pore volume, which contains water. The water saturation of a formation can vary from 100% to a small value, which cannot be displaced by oil, and is referred to as irreducible water saturation SWirr. For practical purposes it can be assumed that the oil or hydrocarbon saturation of the formation SO is equal to SO=1−SW. Obviously, if the formation's pore space is completely filled with water, that is if SW=1, such a formation is of no interest for the purposes of an oil search. On the other hand, if the formation is at SWirr it will produce all hydrocarbons and no water. Finally, the permeability K of a formation is a measure of the ease with which fluids can flow through the formation, i.e., its producibility.
In recent years nuclear magnetic resonance (NMR) logging has become very important for purposes of formation evaluation and is one of the preferred methods for determining formation parameters. Improvements in the NMR logging tools, as well as advances in data analysis and interpretation allow log analysts to generate detailed reservoir description reports, including clay-bound and capillary-bound related porosity, estimates of the amounts of bound and free fluids, fluid types (i.e., oil, gas and water), permeability and other properties of interest.
The importance of Nuclear magnetic resonance (NMR) logging, at least in part, is due to the fact that unlike nuclear porosity logs, the NMR measurement is environmentally safe and is unaffected by variations in matrix mineralogy. The NMR logging method is based on the observation that when an assembly of magnetic moments, such as those of hydrogen nuclei, are exposed to a static magnetic field they tend to align along the direction of the magnetic field, resulting in bulk magnetization. The rate at which equilibrium is established in such bulk magnetization upon provision of a static magnetic field is characterized by the parameter T1, known as the spin-lattice relaxation time. Another related and frequently used NMR logging parameter is the so called spin-spin relaxation time constant T2 (also known as transverse relaxation time) which is an expression of the relaxation due to non-homogeneities in the local magnetic field over the sensing volume of the logging tool.
NMR tools used in practical applications include, for example, the centralized MRIL® tool made by NUMAR Corporation, a Halliburton company, and the sidewall CMR tool made by Schlumberger. The MRIL® tool is described, for example, in U.S. Pat. No. 4,710,713 to Taicher et al. and in various other publications including: “Spin Echo Magnetic Resonance Logging: Porosity and Free Fluid Index Determination,” by Miller, Paltiel, Gillen, Granot and Bouton, SPE 20561, 65th Annual Technical Conference of the SPE, New Orleans, La., Sep. 23-26, 1990; “Improved Log Quality With a Dual-Frequency Pulsed NMR Tool,” by Chandler, Drack, Miller and Prammer, SPE 28365, 69th Annual Technical Conference of the SPE, New Orleans, La., Sep. 25-28, 1994. Certain details of the structure and the use of the MRIL® tool, as well as the interpretation of various measurement parameters are also discussed in U.S. Pat. Nos. 4,717,876; 4,717,877; 4,717,878; 5,212,447; 5,280,243; 5,309,098; 5,412,320; 5,517,115, 5,557,200; 5,696,448 and 5,936,405. The structure and operation of the Schlumberger CMR tool is described, for example, in U.S. Pat. Nos. 4,939,648; 5,055,787 and 5,055,788 and further in “Novel NMR Apparatus for Investigating an External Sample,” by Kleinberg, Sezginer and Griffin, J. Magn. Reson. 97, 466-485, 1992; and “An Improved NMR Tool Design for Faster Logging,” D. McKeon et al., SPWLA 40th Annual Logging Symposium, May-June 1999. The content of the above patents is hereby expressly incorporated by reference for all purposes, and all non-patent references are incorporated by reference for background.
Of the above mentioned patents, U.S. Pat. No. 5,280,243 to Miller discloses an NMR apparatus and method of use for geophysical examination of a bore-hole as it is being drilled. In operation, the apparatus connected to the drill bit generates a gradient static magnetic field in a region of the bore hole adjacent the apparatus. This static field extends radially with respect to the longitudinal axis of the apparatus and has a, generally, uniform amplitude along the azimuth with respect to that axis. Typically, a pulsed radio frequency magnetic field excites nuclei in a substantially cylindrical shell around the tool that defines in the formation a sensitive region extending along the length of the tool and having thickness of about 1 mm. Due to this relatively narrow sensitive region, standard wireline NMR relaxation time measurements are difficult to perform with this tool because lateral vibrations during the measurement time would reduce the accuracy of the measurement.
Another U.S. Pat. No. 5,557,201 to Kleinberg et al. discloses a pulsed NMR device in which the accuracy of the measurement with respect to lateral tool vibrations is enhanced by providing a larger sensitive region. This is achieved by a special tool architecture using two tubular permanent magnets with same poles facing each other, and an antenna positioned in the recess between the two magnets. In operation, this tool architecture provides a sensitive region in the formation, which is larger laterally, but greatly reduced along the borehole axis with vertical tool motions adversely affecting the accuracy of the tool measurements.
Another U.S. Pat. No. 6,051,973, assigned to the assignee of this application, which is incorporated herein in its entirety for all purposes, discloses a method and system for measuring a saturation-recovery sequence to reduce errors due to the motion of the logging tool. Motion-independence is achieved, for instance, by issuing a broad-band saturation pulse that covers a large volume within the sample, followed by a narrow-band read-out sequence such that the narrow-band is within the broad-band.
The MRIL® tool is capable of performing a variety of borehole NMR logging measurements the accuracy of which can be improved using the method of the present invention. See, for example, the U.S. Pat. No. 6,242,912 B1, which is a file wrapper continuation of U.S. application Ser. No. 08/542,340, now abandoned, assigned to the assignee of the present application, which teaches systems and methods for lithology independent gas detection. U.S. Pat. No. 6,005,389 assigned to the assignee of the present application and which was filed Mar. 13, 1997 claiming priority of provisional application Ser. No. 60/013,484, teaches, among other things, the use of a rapid-fire CPMG pulse sequence to detect and quantify components having very short relaxation times, such as clay-bound water. The entire content of these patents is hereby expressly incorporated by reference. These and other NMR measurement methods using the MRIL® tool, as well as measurement methods using the Schlumberger CMR tool, can be improved when performed in conjunction with the method of the present invention.
NMR tools of the type discussed above generally measure the time for hydrogen nuclei present in the earth formation to realign their spin axes, and consequently their bulk magnetization, either with an externally applied magnetic field, or perpendicularly to the magnetic field, after momentary reorientation due to the application of specific radio frequency (RF) pulses. The externally applied magnetic field is typically provided by a magnet disposed in the tool. The spin axes of the hydrogen nuclei in the earth formation are, in the aggregate, caused to be aligned with the magnetic field induced in the earth formation by the magnet. The NMR tool includes an antenna positioned near the magnet and shaped so that a pulse of radio frequency (RF) power conducted through the antenna induces a magnetic field in the earth formation orthogonal to the field induced by the magnet. The RF pulse has a duration predetermined so that the spin axes of the hydrogen nuclei generally align themselves perpendicular both to the orthogonal magnetic field induced by the RF pulse and to the externally applied magnetic field. After the pulse ends, the nuclear magnetic moment of the hydrogen nuclei gradually relax, i.e., return to their alignment with the externally applied magnetic field; at the same time an antenna, which is typically the same as the one used by the initial pulse, is electrically connected to a receiver, which detects and measures voltages induced in the antenna by precessional rotation of the spin axes of the hydrogen nuclei.
An actual NMR measurement involves a plurality of pulses grouped into pulse sequences, most frequently of the type known in the art as Carr-Purcell-Meiboom-Gill (CMPG) pulsed spin echo sequences. As known in the art, each CPMG sequence consists of a 90-degree (i.e., π/2) pulse followed by a large number of 180-degree (i.e., π) pulses. The 90-degree pulse rotates the proton spins into the transverse plane and the 180-degree pulses generate a sequence of spin echoes by refocusing the transverse magnetization after each spin echo.
It should be apparent that it is important for the NMR measurements to register only signals that are generated by the formation of interest. However, non-formation signals—often referred to as “offset” or “ringing” signals—arise for a variety of reasons. For example, they may be caused by the high-sensitivity tool electronics (e.g., “offsets”), or may be due to magnetostrictive effects (e.g., “ringing”) that arise from interactions between pulsed magnetic fields and electronic or magnetic components in the tool. For example, when RF pulses are applied to the antenna, the magnet or antenna can become physically deformed by magnetostriction. After each RF pulse is turned off, the magnet tends to return to its original shape in a series of damped mechanical oscillations, known as “ringing.” Ringing induces voltages in the antenna, which can interfere with measurement of the voltages induced by the spin echoes.
A method known in the art for reducing the effect of offsets, ringing and possibly other non-formation signals is to make spin echo measurements in predetermined cycles. Typically, two pulse sequences of opposite phase are acquired to cancel electronic offsets and 180-degree ringing. The pair of pulse sequences is called a phase-alternated pair (PAP). PAP measurements are performed by making a second set of spin echo measurements starting with an original transverse alignment (90 degree) RF pulse, which is inverted in phase from the 90 degree pulse used to start the first set of spin echo measurements. Voltages induced in the antenna during the second set of spin-echo measurements are inverted in polarity from the voltages induced in the first set of measurements. The signals from the second set of measurements can then be subtracted from the signals in the first set of measurements to substantially remove coherent noise, such as the ringing-induced signals. (For simplicity, in the following discussion “ringing” will be used as a catch-all term designating undesirable non-formation signals). Accordingly, in the “PAP method” successive echo-train signals are acquired from the formation that are alternately in-phase and anti-phase with respect to signals that are generated outside the formation; thus, a typical PAP simply comprises any adjacent pair of in-phase and anti-phase CPMG echo-trains. An implicit assumption in this operation is that the tool-related, non-formation signals in an echo-train can somehow be characterized, and that they change little, or even not at all, between successive echo-trains.
Mathematically, the PAP method can be illustrated as follows. Suppose that an individual spin echo train (CPMG0) can be characterized as a summation of a decaying NMR signal from the formation (S0), a non-formation signal (O0), and random or thermal noise (n0), so that CPMG0=S0+O0+n0. The subsequent phase-alternated echo-train (CPMG1), is then given by CPMG1=−S1+O1+n1. Since changes in the non-formation signal are assumed to be minimal, the difference between the two echo-trains (PAP) cancels the non-formation signals, leaving an echo-train that is a composite of the signals and the noise, i.e.:PAP=(S0+S1)+nΔ
Accordingly, in the prior art non-formation noise is removed using the above PAP process, in which one or more phase alternate pair signals are subtracted to remove the ringing. The two acquisition sequences in each phase alternate pairs must be separated in time by TW, the time to repolarize the media. During logging, the tool is moving at a speed v, so that the PAPs are separated by a distance equal to v*TW. Clearly, this limits the vertical resolution achievable with the tool.
It is thus apparent that to minimize or ideally eliminate non-formation components of the input signal, in accordance with the prior art it is the PAP, rather than the individual echo-train that becomes the basic measured element, which is then processed in similar manner to NMR echo-trains acquired in a laboratory. A potential advantage of the prior art method is that it results in increased SNR of the output signal due to the averaging operation. As discussed above, however, using PAPs as opposed to single echo trains as basic measurement units also introduces a delay that places various constraints on both the achievable logging speed and the vertical resolution of NMR logs.
As noted, prior art methods use a single operation to accomplish both the ringing elimination, as well as the signal-to-noise improvement by means of experiment stacking. One requirement of the prior art methods is to select an amount of stacking necessary for a desired SNR that includes, with equal weight, every PAP at every acquired frequency. This is typically referred to as “boxcar” filtering of the data. For an NMR tool operating at a single frequency, the number of PAPs stacked is simply one or more. For NMR logging tools, such as the MRIL® Prime, operating at N frequencies, the numbers of PAPs stacked must be a multiple of N. Since each PAP comprises two echo-trains, the minimum stacking for the MRIL® tool is two times the number of acquired frequencies. There are two problems associated with this approach. First, in formations with high signal-levels, the approach results in more stacking than is necessary to provide adequate signal-to-noise ratio. On the other hand, for those formations with lower signal-levels, in which more stacking is required to obtain adequate SNR, it is necessary to select an amount of stacking, which is a multiple of the minimum stacking. This is undesirable at least because the extra averaging introduces undesirable processing delays and, as shown below, reduces the maximum vertical resolution.
As shown in the detailed disclosure, in accordance with the present invention an alternative approach can be used where the ringing and random noise components are processed in two steps with possibly different filters. The results show that the (vertical) resolution of NMR logs can be improved in many cases. The output of the proposed processing method is consistently less noisy and more robust even in those cases where there is not a significant vertical resolution improvement compared to the conventional boxcar filter approach.
Focusing next on another deficiency associated with the prior art, as a consequence of the PAP method, the “best-possible” effective vertical resolution of an NMR log acquired with a moving tool is a combination of both the inherent vertical resolution of the tool antenna—the antenna aperture—and the distance traveled between the pair of echo-train measurements that comprise a PAP. As discussed above, however, in many logging situations the vertical resolution is further compromised by the need to average data from multiple PAPs to ensure an adequate signal-to-noise ratio (SNR) for confident data analysis. For example, it is known in the art to improve the SNR of NMR well logging measurements by averaging a plurality of PAPs, typically eight or more.
Depending on the specific “PAP accounting method” employed, echo-trains can form PAPs in a number of different ways. For example, in one method, two adjacent echo-trains form a single PAP, three adjacent echo-trains form two PAPs, and four echo-trains form three PAPs. In an alternative method, while two adjacent echo-trains still form a single PAP, four adjacent echo-trains might be needed to form two PAPs, with six adjacent echo-trains needed to form three. See FIG. 11A. Illustrated in the figure is the “overlapping” mode of operation (of the CMR tool discussed above), where one PAP is acquired every sample interval. As illustrated, in an overlapping mode the two CPMGs overlap half of the sample interval, and the tool relies on the wait time to polarize the hydrogen spins for the NMR measurement. The logging speed (v) of the tool depends on a number of factors, primarily the sample interval and the measurement wait time.
As shown in FIG. 11B in a different embodiment of the CMR tool (CMR Plus), to speed up the measurements the tool uses a new measurement sequence called a sequential PAP. As illustrated, the tool acquires a single CPMG per sample interval, and the phase of each successive CPMG is shifted 180 degrees. A PAP is formed every sample interval by combining the most recent CPMG with the prior CPMG. This measurement sequence allows the tool to move faster, however, it is apparent that the number of independent CPMGs is reduced, which increases the noise level.
In earlier models of the MRIL® tool, the typical logging speed used to acquire NMR data is sufficiently low, so that the effective vertical resolution of the NMR log is dominated by the need to stack multiple PAPs to obtain adequate SNR. For the multi-frequency MRIL® Prime tool, however, the use of multiple NMR measurement frequencies is conceptually equivalent to the simultaneous acquisition of multiple passes with the earlier logging tools. Thus, MRIL® Prime logs could be acquired at faster logging speeds, with the required SNR obtained by stacking multiple PAPs across the frequency bands.
Unfortunately, in high-signal formations (e.g., high porosity, oil-or water-filled rocks), where the logging speeds can be comparatively fast, the effective vertical resolution of the NMR log becomes dominated by the tool movement during a single PAP. For example, with a recovery time of 10 seconds between echo-trains in a PAP, with PAPs acquired at all possible frequencies, the elapsed time between the first echo-train in the first-frequency PAP and the second echo-train for the last-frequency PAP, is close to 20 seconds. At a logging speed of 900 ft/hr (15 ft/min), the MRIL® tool will move approximately 5 feet during this measurement: when combined with the inherent vertical resolution of the antenna (which is approximately 2 feet), the effective vertical resolution becomes roughly 7 feet.
Enhancing the resolution of the logs is a significant problem, because subsurface formations are generally heterogeneous, so that porosity, saturation and lithology vary with position. A common example of heterogeneity is the presence in the formation of geological layers, or beds. Because logging tools have a nonzero volume of investigation, more than one layer may lie within the volume of investigation of a tool. In such cases, the petrophysical evaluation of one layer may be distorted by the presence of another layer falling within the larger volume of investigation of the tool. The above phenomenon leads to a specific problem in the analysis of subsurface formations that include one or more underground layers, especially when the layers are thin compared with the vertical resolution of the measuring tool. Such layers have become subject to significant commercial interest because of their production potential. Any knowledge about the composition and properties of such layered formations that helps better estimate their production potential has thus become increasingly valuable.
Clearly, to make the best use of the NMR logging tools, it is necessary that the current reliance on the PAP as the basic measured element be reduced. Clearly, if for example the MRIL® Prime data can be acquired and/or processed in such a manner that a single echo-train, rather than a PAP, becomes the basic unit of measurement, then it becomes possible to provide an NMR log with an effective vertical resolution much closer to the inherent resolution defined by the length of the tool antenna. Using the assumptions in the example above, if it was only necessary to stack echo-trains from four frequencies to obtain adequate SNR, the elapsed time of the measurements would be about 5 seconds, during which time the MRIL® tool would move approximately 1 foot, resulting in the effective vertical resolution of the NMR log of approximately 3 feet. It is clear therefore that any mechanism that for a given SNR supported by the formation can increase the vertical resolution of the tool without decreasing the logging speed is highly desirable.
Turning to the measured signal from the error and speed related concerns, an important measurement parameter used in NMR well logging is the formation diffusion D. Generally, diffusion refers to the motion of atoms in a gaseous or liquid state due to their thermal energy. The diffusion parameter D is dependent on the pore sizes of the formation and offers much promise as a separate permeability indicator. In a uniform magnetic field, diffusion has little effect on the decay rate of the measured NMR echoes. In a gradient magnetic field, however, diffusion causes atoms to move from their original positions to new ones, which moves also cause these atoms to acquire a different phase shifts compared to atoms that did not move, and will thus contribute to a faster rate of relaxation. Therefore, in a gradient magnetic field diffusion is a logging parameter, which can provide independent information about the structure of the geologic formation of interest, the properties of the fluids in it, and their interaction.
It has been observed that the mechanisms, which determine the values of T1, T2 and D depend on the molecular dynamics of the sample being tested. In bulk volume liquids, typically found in large pores of the formation, molecular dynamics is a function of molecular size and inter-molecular interactions, which are different for each fluid. Thus, water, gas and different types of oil each have different T1, T2 and D values. On the other hand, molecular dynamics in a heterogeneous media, such as a porous solid which contains liquid in its pores, differs significantly from the dynamics of the bulk liquid and generally depends on the mechanism of interaction between the liquid and the pores of the solid media. It will thus be appreciated that a correct interpretation of the measurement parameters T1, T2 and D can provide valuable information relating to the types of fluids involved, the structure of the formation and other well logging parameters of interest.
A major barrier to using NMR logging alone for determination of porosity and other parameters of interest in the past has been the widespread belief that a near-wellbore NMR measurement cannot detect hydrocarbon gases. Failure to recognize such gases may result in their contribution being misinterpreted as bound fluid, which mistake may in turn result in excessively high irreducible water saturations and correspondingly incorrect permeability estimates. It has recently been found, however, that the NMR properties of gas are in fact quite different from those of water and oil under typical reservoir conditions and thus can be used to quantify the gas phase in a reservoir. More specifically, the Magnetic Resonance Imaging Log (MRIL®) tools of NUMAR Corporation have registered the gas effect as distortion in the bound volume irreducible (BVI) and/or free fluid index (FFI) measurements.
In the paper, entitles “NMR Logging of Natural Gas Reservoirs,” paper N, presented at the 36th Annual SPWLA Symposium, Paris, Jun. 26-29, 1995, Akkurt, R. et al. have shown one approach of using the capabilities provided by NUMAR's MRIL® tool for detection of gas. The content of the Akkurt et al. paper is incorporated herein for all purposes. In this paper, the authors point out that NMR signals from gas protons are detectable, and derive T1 relaxation and diffusion properties of methane-dominated natural gas mixtures at typical reservoir conditions. The magnetic field gradient of the MRIL® is used to separate and to quantify water, oil and gas saturations based solely on NMR data.
The results in the Akkurt paper are based on the NUMAR MRIL-C tool, the output of which is used to obtain T2 spectra. T2 spectra are extracted from the raw CPMG echo trains by breaking the total NMR signal M(t) into N components, called bins, according to the formula:       M    ⁡          (      t      )        =            ∑              i        =        1            N        ⁢                  a        i            ⁢              exp        ⁡                  (                                    -              t                        /                          T              2                                )                    where ai is the porosity associated with the i-th bin. Each bin is characterized by a fixed center transverse relaxation time T2l. The total NMR porosity is then determined as the sum of the porosities ai in all bins. The T2 spectrum model is discussed in detail, for example, in Prammer, M. G., “NMR Pore Size Distributions and Permeability at the Well Site,” paper SPE 28368, presented at the 69-th Annual Technical Conference and Exhibition, Society of Petroleum Engineers, New Orleans, Sep. 25-28, 1994, the content of which is expressly incorporated herein for all purposes.
On the basis of the T2 spectra, two specific methods for gas measurements are proposed in the Akkurt paper and will be considered briefly next to provide relevant background information. The first method is entitled “differential spectrum method” (DSM). The DSM is based on the observation that often light oil and natural gas exhibit distinctly separated T2 measurements in the presence of a magnetic field gradient, even though they may have overlapping T1 measurement values. Also, it has been observed that brine and water have distinctly different T1 measurements, even though their D0 values may overlap. The DSM makes use of these observations and is illustrated by a specific example for a sandstone reservoir containing brine, light oil and gas. According to the Akkurt et al. paper, two separate logging passes are made with different wait times TR1, and TRs, such that the longer time TR1≧T1g, and the shorter time satisfies the relationship T1g≧TRs≧3T1wmax.
Due to the large T1 contrast between the brine and the hydrocarbons the water signal disappears when the spectra of the two signals are subtracted. Thus, the differential T2 spectrum contains only hydrocarbon signals. It should be noted that the subtraction of the T2 spectra also eliminates all bound water, making the DSM very useful in shaly sands.
The second method proposed in the Akkurt et al. paper is called “shifted spectrum method” (SSM). Conceptually the method is based on the observation that since the surface relaxation for gas is negligible, the apparent T2 relaxation can be expressed as:       1          T      2        =            1              T                  2          ⁢          b                      ⁡          [              1        +                                                            (                                  γ                  ⁢                                                                           ⁢                  G                  ⁢                                                                           ⁢                  τ                                )                            2                        ⁢                          DT                              2                ⁢                B                                              2                    ]      where G is the magnetic field gradient, D is the diffusion coefficient, τ is half the interecho time, γ is the gyromagnetic ratio and T2B refers to the bulk relaxation. It is known in the art that for gas, which is a non-wetting phase, T1=T1B≈T2B. Therefore, given that the product D0,T1 of a gas after substitution in the expression above is an order of magnitude larger than oil and two orders of magnitude larger than brine, it can be seen that the already large DT1 contrast of gas can be enhanced even further by increasing the interecho time 2τ in order to allow the separation of two fluids that overlap in T1. The SSM is based on the above concept and may result in the signal from gas being shifted out of the detectability range, so that the single spectrum peak is due to brine.
While the DSM and the SSM methods discussed in the Akkurt et al. paper and briefly summarized above provide a possible working approach to detection of gas using solely NMR data, the methods also have serious disadvantages which diminish their utility in practical applications. Specifically, due to the fact that two separate logging passes are required, the Akkurt methods show relatively poor depth matching properties on repeat runs. Furthermore, subtraction of signals from different logging passes is done in the T2 spectrum domain which may result in losing valuable information in the transformation process, especially when the received signals have low signal-to-noise ratios (SNRs). In fact, for a typical logging pass, low hydrocarbon index (HI) of the gases in the formation, and relatively long T1, times generally lead to low SNR of the received signals. After transformation into the T2 spectrum domain even more information can be lost, thus reducing the accuracy of the desired parameter estimates. Finally, the Akkurt et al. paper does not indicate ways of solving additional problems such as accounting for low gas saturation in the sensitive volume, the presence of gases other than methane, and the temperature dependency of the filed gradient.
While techniques have been developed in the prior art to extract information about the structure and the fluid composition of a geologic formation, so far no consistent NMR well logging method has been proposed to accurately and efficiently interpret these measurement parameters by accounting for the different effects of individual fluids and various sources of error. This often leads to inaccurate or misleading log data interpretation, which, in turn, can cause costly errors in the oil exploration practice. Therefore, there is a need for a NMR system and method for providing consistent and accurate evaluation of geologic formations using a combination of substantially simultaneous log measurements to take into account the effects of different fluids. Since in the presence of very high ringing amplitudes (100%-200% of full scale NMR signals), the residuals from phase- and frequency-alternation are still strong enough to affect the final result (a 200% ringing signal, cancelled with 98% efficiency, can result in about +/−4 p.u. (porosity unit) error in the final result) it is desirable to measure both the efficiency of the ringing cancellation and the amplitude and phase (i.e sign) of the ringing residual with respect to the NMR signal. This can serve as a quality control indicator as well as leading to additional corrective measures or avoidance of unnecessary corrective measures.